Various fluids or muds are used in oil and gas well drilling and operation. Such fluids are used to preventing the entry of solids into the subterranean formation, which could decrease the permeability of the formation, (2) using well completion fluids that do not tend to swell and/or disperse formation particles contacted by the completion fluid, (3) preventing the entry of formation particles into the perforations, and (4) avoiding excessive invasion of wellbore fluids into the formation. Specially formulated fluids are used in connection with drilling, completion, workover and other wellbore operations. Completion fluids are used after drilling is complete and during the steps of completion, or recompletion, of the well, such as cementing the casing, perforating the casing, and setting the tubing and pump. Workover fluids are used during remedial work in the well, such as removing tubing, replacing a pump, logging, reperforating, and cleaning out sand or other deposits. Many such treating fluids are aqueous or brine-based fluids. The fluid composition for a particular application generally depends on such considerations as fluid density, viscosity—to achieve desired solids-carrying capacity, and fluid loss control—to prevent excessive loss of fluid from the wellbore to the formation.
Effective viscosity and fluid loss control for temperatures below about 350° F. have been achieved by the addition of polymers to aqueous or brine-based fluids. Various chemicals are added to obtain the desired effects, including for example carboxymethyl cellulose, hydroxyethyl cellulose, xanthan gum, guar gum, polyanionic cellulose, and hydroxypropyl guar gum. Bridging agents have been added to the fluid together with polymers for fluid loss control, to form a bridge on the formation face to prevent fluid loss. The problem of fluid loss is increased at high temperatures and pressures encountered in deep wells.
Well servicing fluids have been suggested, such as in U.S. Pat. No. 5,620,947, including fluid composition using brines containing water soluble salts in particulate size, sometimes called “sized-salt.” The fluids suggested there are said to be produced from a saturated brine solution, a water soluble sized salt that is insoluble in the saturated brine solution, and a water soluble polymer produced from at least two monomers of 2-acrylamido-2-methylpropanesulfonate, acrylamide or 2-vinylpyrrolidone, where the fluid is exposed to temperatures above 400° F. These fluids are said to address the known problem that polymer products used to suspend the salt particles and to supplement the bridging of salt particles are not temperature stable at temperatures above about 300° F. These higher temperatures can cause breakdown of viscosifiers and filtration control additives. For example, starch and xanthan gum degrade at about 225° F. to 250° F., carboxymethyl cellulose and guar gum degrade at about 250° F. to 300° F., and lignosulfonates begin to degrade at about 250° F. and are particularly unstable above about 325° F. Without adequate filtration control, formation damage can result.
The search for oil and gas has led to the drilling of deeper wells in recent years. Because of the temperature gradient in the earth's crust, deeper wells have higher bottomhole temperatures. A good workover and completion fluid should be Theologically stable over the entire range of temperatures to which it will be exposed, in order to suspend the particulate filtration and bridging additives. In deep wells, this can exceed 400° F. or even 425° F. or higher. Accordingly, there is a need for improved wellbore fluids, particularly for fluids that provide good viscosity and are thermally stable at temperatures above 400° F. or even 425° F. or higher.
In order to achieve a suitable density for use in well-drilling or other well servicing operations, it is conventional to use soluble polymers, such as polysaccharide polymers, in compositions further including water soluble salts, e.g., as described in UK patent 1,549,734 and U.S. Pat. No. 4,900,457. These salts are typically halide salts (e.g. chlorides and bromides) of mono- or divalent cations, such as sodium, potassium, calcium and zinc. Conventional water soluble polymers have deficiencies in typical uses. When the polymers are exposed to shearing conditions they are physically degraded to lower molecular weight polymers, thereby reducing the viscosity of the aqueous solution containing the polymers. In addition, aqueous solutions containing ionic water soluble polymers exhibit viscosity reduction when electrolytes are introduced to the solution, as is common in enhanced oil recovery. Finally, exposure of such aqueous solutions to high temperatures causes an undesirable degree of reduction in viscosity.
It is known to attach hydrophobic groups to polymers to modify the viscosity of an aqueous media solution containing the polymer. These rheology modifiers are generally known as associative polymers or hydrophobe associative polymers. In particular, these hydrophobized polymers in certain systems or solutions increase low shear thixotropy, high shear thinability, high solids loading, resistance to mechanical degradation and impart lubricity. Certain aqueous soluble hydrophobe associative copolymers are shown in published patent application WO 85/03510, the entire disclosure of which is hereby incorporated herein by reference in its entirety for all purposes. The copolymers of WO 85/03510 are said to be formed of an ethylenically unsaturated, water soluble monomer and an ethylenically unsaturated amphiphilic monomer having hydrophobic moieties that are capable of associating with each other in an aqueous medium containing a water soluble electrolyte. The copolymers are discussed for use in an aqueous medium together with such electrolyte and other ingredients common to mobility control fluids, fracturing fluids and drilling muds.
As noted above, a problem still faced in well drilling and other well servicing operations relates to thermal stability of well service fluids, such as completion fluids, work-over fluids and drilling fluids or muds, and especially thermal stability coupled with high density and viscosity. Temperatures in subsurface formations generally rise approximately 1° C. per hundred feet (30 meters) depth. Known aqueous polysaccharide compositions each has its own characteristic temperature above which it undergoes substantial degradation with undesirable reduction of viscosity, thus imposing limitations on its use in drilling operations below a corresponding depth. Additives, for example, blends of polymeric alkaline materials such as that sold by International Drilling Fluids (UK) Ltd., under the trademark “PTS 200,” have been used to improve thermal stability of aqueous polysaccharide compositions. There remains a substantial need for good well service fluids that are thermally stable at high temperature, have good density and exhibit high and durable viscosity.
It is an object of the present invention to provide polymers and compositions meeting some or all of the industrial needs identified above. It is also an object of the invention to provide well servicing methods and the like employing such polymers and compositions.